Tank fire and loss data from a major integrated oil company over several years indicated it was averaging about 20 tank fires per year resulting in property loss and an injury. Slightly more than half of the fires were in the downstream segment and excluding small tanks, and 90 percent of the fire loss related to operating and maintenance procedures. There were three fully involved fires. Because many new terminals are being constructed today there are a number of best practices that should be considered in the early front-end engineering design planning stages of terminal projects. Some key best practices are listed:
• Ensure drainage and tank spacing requirements listed in NFPA 30 are set up in the design criteria.
• Tank yard drainage must not accumulate under pipeways or near tanks especially for safety critical control wiring and communications. This assists in reducing corrosion as well as minimizing the chance a fire escalates.
• Review drainage channels and culverts to remote impound areas designed for worst case overflow and spill rates. Undersized equipment causes fire spread. Do not size for tank rupture as this is an unrealistic scenario.
• Seal all piping penetrations through dike walls with fire retardant material. Use non-combustible water stops to seal joints in concrete dike walls. Design dikes for hydraulic integrity when completely full.
• Sample lines have root valves and they are accessible for tank isolation in the event of a fire.
• Size fire mains for the largest potential tank fire.
• Provide water shell cooling over 50 percent of the tank periphery using NFPA 11 flow rates plus a safety factor, cooling for a fully involved tank fire with water for 25 percent of the circumference of the top half of the involved tank plus cooling for three adjacent tanks within 75 feet of the involved tank.
• Locate hydrants so all parts of tank shells can be reached by hose lines not longer than 500 feet, can provide cooling to any tank from two directions and ensure hydrant is at least 50 feet from the edge of the tank impound.
• Implement API 500 electrical area classification requirements.
• Implement the fourth edition of API 2350 to reduce likelihood of tank overfills.
• Make sure tank filling, withdrawing and water draw nozzles are not installed beneath stairways or platforms.
• Butterfly valves to have enclosed bolt lugs so there are no exposed bolts.
• Tank attached piping is flexible to accommodate future settlement.
• Emergency venting on all tanks under 50 feet in diameter not using frangible roofs.
• No floating pan roofs. Use annular pontoon or double deck floating roofs for external floating roof tanks per API 650 Appendix C roofs for external floating roofs. Cover tanks with domes or cones in high lightning areas for reduced fire risk based on industry learnings.
• Consider using a windgirder walkway combination for tanks more than 120 feet in diameter that provide access to firefighters in the event of rim seal fires.
• Pumps are ignition sources so ensure pumps are installed outside the secondary containment. If necessary to have a hydrocarbon pump inside, then consider measures like fire detection or mitigation. Also, check local code requirements.
• No combustible materials installed inside the secondary containment.
• Consider remote operated manual valves when it would be hazardous to isolate a tank during emergency response situations.
• Set up plans to periodically test all emergency response systems, valves and operations. This guidance does not apply to LPG or LNG storage.
For more information on the National Institute for Storage Tank Management, visit www.nistm.com or call (800) 827-3515. For more information on this topic, contact Phil Myers at phil@pemyconsulting.com.
